This rulemaking continues the implementation of Senate Bill (SB) 1078, which created the California Renewables Portfolio Standard (RPS) Program.1 This Commission began the implementation of the RPS Program in Decision (D.) 03-06-071, and also stated that it would open a new rulemaking to continue that process. This is that new rulemaking. All open issues relating to the implementation of the RPS program will be addressed in this proceeding.2

There are a number of tasks that must be completed promptly to enable the first round of RPS solicitations to occur. This rulemaking sets out a process to complete those tasks, sets forth some basic assumptions, and continues the movement toward implementation of the RPS program. We establish baseline levels of renewable generation for each utility as a proportion of their total generation portfolio, and set the Annual Procurement Target (APT) that each utility must meet this year. The Commission anticipates that the first RPS solicitation will take place by July 1, 2004.

In the longer term, there are many more tasks to be done and issues to be addressed, but the time frame is slightly less pressing. Accordingly, we will identify those tasks and issues as we see them today, but the process for addressing them, and any additional ones that may arise, will be delegated to the Assigned Commissioner and Administrative Law Judge (ALJ). As its moves forward, this proceeding will coordinate with other relevant proceedings, such as the new rulemaking on avoided costs and the other proceedings under the general case management umbrella of our procurement rulemaking.3

Background

On August 22, 2002, the Commission issued D.02-08-071 that ordered, among other things, a separate renewables solicitation by each utility for at least an additional one percent of their actual energy and capacity needs. This was roughly equivalent to the RPS program approach enacted in SB 1078. D.02-08-071 was issued in anticipation of SB 1078's passage, and the decision's requirements were conformed to the language of the bill, even though our authority to order the solicitation derived from Pub. Util. Code § 701.3.

The Commission has since approved twenty-two renewable contracts from the transitional procurement activity authorized by D.02-08-071: PG&E (7) in Resolutions E-3805 and E-3853; SCE (5) in E-3809, E-3814, and E-3816; and SDG&E (15) in E-3803.

Short Term Issues

Our immediate goal is to ensure that the utilities will be able to issue Requests for Offers (RFOs) by July 1, 2004, and that renewable generators will be able to prepare and submit bids in response to those RFOs. We emphasize that this is the first solicitation in a multi-year program of renewable energy development, and this Commission will inevitably need to revisit aspects of the RPS program as we gain more experience with the program, and as the renewable generation industry continues to evolve. In order to meet our immediate objective of an RPS solicitation as soon as possible, however, there are specific tasks that the Commission must complete or at least move close to resolution.

Those tasks include: quantifying the amount of renewable generation in each utility's present portfolio (the "baseline"), establishment of annual procurement targets (APTs) for each utility for 2004, adoption of standardized contract terms and conditions (including the definition of a renewable energy credit (REC)), finalizing the Market Price Referent (MPR) methodology, and further development of the least-cost and best-fit evaluation process (which includes other tasks, such as the development of transmission adders, capacity values, and integration costs).

1. Baseline

The definition of the RPS generation baseline comes from Pub. Util. Code § 399.15(a)(3) and includes all eligible renewable generation in the utility's portfolio as a percentage of 2001 retail sales. We update the baseline figures to include renewable generation procured in the period between legislative enactment of the RPS and the issuance of this new rulemaking.

These figures are based on utility self-reporting. We intend to provide for detailed public disclosure of these baseline figures, down to the level of each plant and generation technology, when the immediate task of preparing for the first RPS solicitation is accomplished. These baseline figures are to be considered interim in nature, and parties will have the opportunity to comment on these figures as described below.

2. Annual Procurement Target

The annual procurement target (APT) is the amount of renewable generation a utility must procure in order to meet the statutory requirement that it increase its renewable procurement by at least 1 percent of retail sales per year.7 Annual procurement targets are mandatory (id., pp. 41-42)8, and consist of two separate components: the baseline, described above, representing the amount of renewable generation a utility must retain in its portfolio to continue to satisfy its obligations under the RPS targets of previous years; and the incremental procurement target (IPT), defined as at least 1% of the previous year's total retail electrical sales, including power sold to a utility's customers from its DWR contracts.

In order to ensure that the utilities make steady progress towards the 20% RPS goal, this Commission previously stated that the RPS obligation is to both maintain the baseline level of renewable procurement and to satisfy the IPT in each year.9 In short, the amount of generation contained in these two components together is what the utility must procure in order to satisfy its annual RPS obligation.

Below we set forth the 2004 APT for each utility based on 2003 sales figures, as self-reported by the utilities.10 Should subsequent analysis reveal inaccuracies in our initial definition of the baseline for any utility, we will adjust the APT in subsequent years as appropriate to make up the difference, without penalty to the utility in question.

The APT is the minimum amount of renewable generation the utility must procure each year, subject to the flexible compliance mechanisms authorized in D.03-06-071. Consistent with SB 1078, and as described further in D.03-06-071, utilities are free to procure above this APT and apply any excess generation to APTs in future years. However, the Commission, along with the CEC and CPA, has adopted the Joint Agency Energy Action Plan, which calls for attainment of the 20% RPS goal by 2010. While this is a higher goal than we set in D.03-06-071, we are committed to reaching this objective.

In order to meet this goal, we also provide an estimation of each utility's procurement target for 2004 increased to the level necessary to reach the 2010 target date. While 1% incremental renewable procurement is the requirement for RPS compliance, we encourage the utilities to procure cost-effective renewable generation in excess of their APTs for this year, in order to make progress towards the goal expressed in the EAP.

3. Standard Contract Terms and Conditions

Contrary to the Joint Ruling in R.01-10-024 issued on March 8, 2004,12 the decision adopting standard contract terms and conditions will be issued in this proceeding. On this issue we incorporate the record from that proceeding by reference into the record of this proceeding. The decision adopting the standard contract terms and conditions will also further clarify the role of Renewable Energy Credits (RECs) in satisfying and monitoring compliance with the procurement targets established under the RPS program.

4. Market Price Referent (MPR)

D.03-06-071 set out the fundamental framework for the Commission to use in establishing the MPR, which is an essential element in the ranking of RPS bids

and in the distribution of Supplemental Energy Payments by the CEC. The decision directed staff to prepare a white paper on further MPR development and to convene a workshop on these issues, both of which have been accomplished. Parties will have an opportunity to comment on the MPR methodology, as described below.13

5. Least-Cost/Best-Fit

Least cost and best fit is the shorthand term established by the RPS legislation to describe the process of bid ranking the utility is to undertake in the RPS program. D.03-06-071 developed the majority of the components of this evaluation, and identified two components for further work. Those two components are establishing capacity values for intermittent technologies and developing bid adders to reflect the cost of transmission needed to connect new renewable generation to the grid.

On the issue of capacity values for intermittent technologies, the Commission directed that the RPS program utilize either the standard approach employed for Qualifying Facility (QF) resources, or, should the results become available in time, the more refined analysis contained in the report, "California Renewables Portfolio Standard Renewable Generation Integration Cost Analysis" (CEC Study) prepared by the California Wind Energy Collaborative under the auspices of the CEC's Public Interest Energy Research Program.14

Phase 1 of the CEC Study is now complete, and we note that many of the same parties in our previous RPS proceeding have participated in reviewing the results at the CEC. Given the importance of this aspect of the program to the full integration of renewable generation into the state's resource portfolio, we direct staff to convene a workshop that will examine the results of Phase 1 of the CEC Study for possible use in the first RPS solicitation.

We reiterate the intention expressed in D.03-06-071 that we will not delay the first RPS solicitation through protracted litigation on this issue. While we would like to use the CEC Study, it is not clear whether we will be able to do so in time for the first RPS solicitation. Accordingly, we will set the capacity values for intermittent technologies using our standard QF methods, as that will move the process forward towards a solicitation by the July 1, 2004 target date, unless the above workshop process actually provides a concrete and expeditious resolution that allows for use of the CEC Study. Should such a resolution occur, with results contained in a workshop report in time to be used for the first RPS solicitation, capacity values for intermittent technologies may be set based on the CEC Study via a joint ALJ and Assigned Commissioner Ruling.

The other element of the least cost- best fit process that was deferred for further study in D.03-06-071 is the development of any necessary bid adders to reflect the cost of transmission to connect new renewable resources to the grid.15 This task was assigned to the Commission's Transmission investigation, I.00-11-001, and is advancing in that proceeding on a schedule that will allow the results to be available to the first round of RPS bidders. Parties not presently participating in that proceeding, particularly prospective RPS bidders with possible transmission costs, should do so as soon as possible so that a transmission adder for the bid can be developed in a timely manner.

Finally, we note that the CEC is charged with certifying eligible resources for participation in the RPS program and for eligibility to receive SEPs. Parties who are interested in submitting RPS bids should obtain the necessary certification from the CEC.

Long-Term Issues

In D.03-06-071, the Commission identified a number of issues that needed further attention. The issues identified (other than those discussed above) were: electric service provider (ESP) participation in the RPS program (id., pp. 58 and 60); community choice aggregator (CCA) participation in the RPS program (id.); definition of the environmental attributes of renewable energy credits (RECs) that must be transferred to the utility for it to meet its RPS obligations (id., pp. 59, 71)16; consequences of inadequate Public Goods Charge (PGC) funds (id., pp. 59-60); treatment of repowering of renewable facilities (p. 60); refinement of penalty and penalty cap levels (p. 60, 73); and availability of penalty funds for use as PGC funds (p. 60).17

In addition, the rules governing eligibility of renewable distributed generation (DG) in the RPS program must be developed and implemented, and the treatment of RECs from QFs must be finalized in light of recent FERC action. (See, Covanta Energy Group et. al., 105 FERC ¶61,004 (2003).)

We must also begin to apply the RPS program to the small and multi-jurisdictional electric utilities that are regulated by this Commission. Accordingly, the small and multi-jurisdictional electric utilities are made respondents to this rulemaking. While not formally respondents to this proceeding, CCAs and ESPs should participate as they are considered retail sellers under Section 399.12.

Finally, we note that the baselines and targets established above do not consider the issue of line losses associated with renewable generation, or the treatment, if any is appropriate, of the RECs associated with such losses. We will consider this issue after the first RPS solicitation is complete, and, recognizing the issue's technical complexity, may make adjustments to our methods of measuring renewable generation in the future.

While all of these issues do need to be addressed, they do not need to be addressed on an expedited basis in order to hold the first RPS solicitation by July 1 of this year. Accordingly, while we reiterate the need to address these issues, the process for addressing them will be left up to the assigned Commissioner and ALJ. We note that we do not intend to revisit issues that were determined in D.03-06-071, so while we may refine our previous determinations and flesh out more details, parties should not expect to re-litigate issues already decided by this Commission.

One key longer-term goal is to more closely coordinate the renewable procurement process with the general procurement process, as contemplated by section 399.14(a). Our processes for addressing renewable and general procurement are moving forward and are converging, and while renewable procurement is out in front right now, we expect that in the near future the two will come together in an integrated manner.

Process

Comments on the baseline numbers set forth above and on the MPR methodology to be used are to be filed and served on April 30, 2004. If a service list in this proceeding is not yet available by that date, service of those comments should be on the service list in R.01-10-024, and may be electronic only, consistent with the attached Electronic Service Protocols.

A prehearing conference to establish a service list and address other procedural issues will be set promptly.

We intend to issue a draft decision in May that incorporates the results of the baseline comment process and the MPR workshop process. The results of the proceeding addressing transmission cost adders may be discussed in that decision, or may be incorporated by reference. The Commission will also provide guidelines for interim renewable procurement plans. We note that, in order to meet the goal of a first RPS solicitation taking place by July 1, 2004, these first interim renewable procurement plans will necessarily be greatly simplified, both in process and in content.

As we move forward, we will coordinate this proceeding with other related proceedings, as described in D.03-06-071 (p. 59) and above, and particularly our general procurement rulemaking. Treatment of confidential information in this proceeding shall be consistent with the policies and procedures developed in the general procurement proceeding, R.01-10-024, and its successor, R.04-04-003.

In the RPS phase of R.01-10-024, our Commission staff worked collaboratively with the staff of CEC. This collaboration proved to be both useful and productive, and we want to expand on that success in this proceeding. We direct Commission staff to explore how to further improve the collaboration process, particularly around the exchange of information between the two agencies. The collaboration process should be consistent in all of our proceedings in which the CEC is acting in a purely collaborative role. The Assigned Commissioner or ALJ may issue a ruling setting forth collaboration guidelines for this proceeding, consistent with our direction.18

Preliminary Scoping Memo

In this Preliminary Scoping Memo, we describe the issues to be considered in this proceeding and the timetable for resolving the proceeding. Principally, this rulemaking is the forum for continuing the implementation of the RPS program. As described above in more detail, all issues relating to the implementation of the RPS program will be addressed in this proceeding.

1 See, Pub. Util. Code §§ 399.11 through 399.16. SB 1078, chaptered on September 12, 2002, requires the Commission to establish a program whereby the utilities must purchase a specified minimum percentage of electricity generated by renewable energy resources. The utilities must increase their total procurement of eligible renewable energy resources by at least one percent per year so that twenty percent of their retail sales are procured from eligible renewable energy resources by December 31, 2017. 2 In previous rulings in R.01-10-024, it was indicated that the initial adoption of standard contract terms and conditions would remain in the procurement (R.01-10-024) docket. In order to consolidate all RPS issues into one proceeding, and to allow for the closing of the old procurement docket, we will address the adoption of standard contract terms and conditions in this docket.3 See, R.04-04-003, pp. 8-10. In particular, we recognize the need to apply consistent input assumptions and valuations of benefits across all resource proceedings, and will ensure that future rounds of the RPS solicitations benefit from the development of a record on these issues in the avoided cost OIR.4 SDG&E Data Sources: 1) 2003 renewable generation - Feb 1, 2004 APT compliance report. 2) 2003 retail sales - email dated 4/5/04 from SDG&E's Joseph R Kloberdanz.5 SCE Data Sources: 1) 2003 renewable generation - Feb 1, 2004 APT compliance report. 2) 2003 retail sales - Feb 1, 2004 APT compliance report.6 PG&E Data Sources: 1) 2003 renewable generation - Feb 1, 2004 APT compliance report plus 2002 renewable generation reported by PG&E in 10/21/2003 response to Energy Division's 10/2/03 data request. 2) 2003 retail sales - Draft FERC Form 1 sales data as of April 9, 2004.7 See, D.03-06-071, p. 7, fn. 9.8 Although there are flexible rules for compliance. Id., pp. 39-54.9 D.03-06-071, p. 47.10 The 2003 sales figures will be finalized when the utilities file their Form 1 reports with the Federal Energy Regulatory Commission (FERC).11 PG&E data estimated from April 15, 2003 Long-Term Plan, Table 5-3; SCE from Long-Term Plan Testimony, Vol. 2, Table III-3; SDG&E 2004 sales increased at 1% annually to 2010. 12 The full title is: "Joint Ruling of Assigned Commissioner and Administrative Law Judge Regarding Procedure for Adoption of Standard Contract Terms and Conditions."13 The MPR white paper, party comments on the paper, and other relevant material can be obtained at
http://www.cpuc.ca.gov/static/industry/electric/renewableenergy/mpr.htm.14 Available online:
http://www.energy.ca.gov/reports/2004-02-05_500-03-108C.PDF15 These costs must be kept separate from the other cost elements in the RPS program due to the requirement that Supplemental Energy Payments not be used to fund transmission upgrades.16 Even thought this issue will be addressed in conjunction with the adoption of standard contract terms and conditions, certain aspects of RECs may need to be examined or re-examined in the future.17 The decision also identified confidentiality of information as an issue (id., p. 58), which is addressed below.18 In R.01-10-024, the collaboration guidelines were set forth in an ALJ Ruling dated February 3, 2003.